Stimulation of wells in nano-darcy shale formations

ABSTRACT

This disclosure describes formulations and methods for stimulating the production from wells in nano-darcy shale formations. In one embodiment, the method includes injecting a treatment mixture containing a metal complexing agent into a nano-darcy shale formation adjacent to a well at a pressure below the fracture pressure of the formation. A sufficient contact time is allowed and then the treatment mixture is pumped from the subsurface. This has been shown to stimulate well production in shale formations. Without being held to a particular theory it appears that the metal complexing agent is binding with naturally occurring metals in the shale formation, and particularly divalent metal ions, which are then extracted with the spent fluid. This removal of naturally occurring metals may be increasing the permeability of the formation in the contact region adjacent to the well, thereby causing the observed increased production.

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.62/087,899, filed Dec. 5, 2014, and U.S. Provisional Application No.61/979,210, filed Apr. 14, 2014, which applications are herebyincorporated by reference.

INTRODUCTION

The darcy is a unit of permeability for fluids in a porous material.Nano-darcy shale formations refer to those shale formations having anaverage permeability in at least one direction of less than 1micro-darcy or less than 1×10⁻⁶ darcy. In nano-darcy shale formations,the range of average pore sizes within the shale spans the size of thehydrocarbons trapped in the shale, e.g., the natural gas molecules andthe molecules of the various crude oil constituents. That is, theaverage pore size within the shale may be smaller, approximately thesame size or larger than the size of the hydrocarbons. This differs fromhigher permeability shale formations in which the average pores sizesare substantially larger than the various hydrocarbon molecule sizes.

While permeability is a useful measurement, the determination of averagepore size from a permeability measurement relies on assumptions aboutthe shapes of the grains or pores in the subsurface. Shale formationsare a mixture of clay minerals and larger particles. Clay minerals arenot normally spherically shaped and also exhibit electro-staticproperties not found in non-clay materials. Thus, as nano-darcy shaleformations are typically very high in clay content, they do not exhibitthe same behaviors as more permeable formations, even more permeableshale formations.

Well stimulation refers to the treatment of an existing well to increaseits recovery of hydrocarbons or other substances from the subsurface.Because of the different nature of nano-darcy shale formations, typicalwell stimulation techniques have been found to be ineffective or muchless effective than in higher permeability formations.

An extreme form of well stimulation is referred to as hydraulicfracturing. Hydraulic fracturing of oil and gas wells is conducted bypumping fluids at high pressures and high velocities through a verticaland, usually, a horizontal section of a well. The well contains a wellcasing and, in some wells, tubing inside the casing. Perforations orports in the casing are adjacent to targeted intervals of subterraneanformations containing a hydrocarbon or target product. In hydraulicfracturing, the pressure exerted on the formation is greater than thepressure required to substantially fracture the formation, a pressurereferred to as the fracture pressure of the formation which is afunction of the formation' properties and the depth where the fracturesare desired. One test for determining the fracture pressure is theLeak-off test. Applying a pressure equal to or greater than the fracturepressure causes the formation to fracture, creating an extensivefracture network.

After the fractures or cracks are initiated, pumping is continued,allowing the fractures to propagate. Once the fracture has gainedsufficient fracture width, a proppant such as sand is added to the fluidand is transported into the fracture system, partially filling thefracture network. After the desired amount of proppant is placed in thefractures, additional water-based fluid is pumped to flush the casing ofany proppant that may have settled in the casing. On completion of thefracturing process, the well is opened, allowing a portion of thefracturing fluids to be recovered. As the pressure is relieved, thefracture closes onto the proppant, creating a conductive pathway neededto accelerate oil and gas recovery from the formation. Hydraulicfracturing is expensive because of the large amounts of fluids and highpressures involved.

STIMULATION OF WELLS IN NANO-DARCY SHALE FORMATIONS

This disclosure describes formulations and methods for stimulating theproduction from wells in nano-darcy shale formations. In one embodiment,the method includes injecting a treatment mixture containing a metalcomplexing agent such as citric acid or EDTA into a shale formationadjacent to a well at a pressure below the fracture pressure of theformation. A sufficient contact time is allowed and then the treatmentmixture is pumped from the subsurface. This has been shown to stimulatewell production in nano-darcy shale formations. In another embodiment,the method includes staging the treatment mixture containing a metalcomplexing agent such as citric acid or EDTA in combination withhydraulic fracturing and injecting into the formation in conjunctionwith propagation of the induced fractures. Without being held to aparticular theory, based on an analysis of the extracted spent treatmentfluid it appears that the metal complexing agent binds with naturallyoccurring metals in the formation, and particularly divalent and/ortrivalent metal ions, which are then extracted with the spent treatmentmixture. This removal of naturally occurring metals may be increasingthe permeability of the formation in the contact region adjacent to thewell, thereby causing the increased production.

In one aspect, this disclosure describes a method for stimulating a wellin a nano-darcy shale formation. The method includes providing atreatment mixture containing between about 0.1% and 95% by weight metalcomplexing agent at a pH of between about 0 and 10; injecting thetreatment mixture into the well at a pressure less than a fracturepressure of the nano-darcy shale formation until at least some of thetreatment mixture contacts the nano-darcy shale formation; maintainingthe treatment mixture in contact with the nano-darcy shale formation fora contact time of between about 1 minute to 100 days, thereby allowingthe metal complexing agent to bind with at least somenaturally-occurring metals contained within the nano-darcy shaleformation; and removing the treatment mixture from the well after thecontact time, thereby removing the bound naturally-occurring metals fromthe non-darcy shale formation and thereby improving the hydrocarbonproduction of the well relative to the hydrocarbon productionimmediately prior to performance of the method. In the method, the metalcomplexing agent may be one or more of citric acid, ethylene diaminetetra acetic acid (EDTA), acetic acid, or any of a number of compoundsdescribed below.

Another aspect of this disclosure is method for fracturing andstimulating a well in a nano-darcy shale formation. The method includesproviding a treatment mixture containing between about 0.1% and 95% byweight metal complexing agent at a pH of between about 0 and 10;injecting the treatment mixture into the well at a pressure greater thana fracture pressure of the nano-darcy shale formation until at leastsome of the treatment mixture enters fractures in the nano-darcy shaleformation, thereby allowing the metal complexing agent to bind with atleast some naturally-occurring metals contained within the nano-darcyshale formation; and removing spent treatment mixture and fracturingfluids from the well after the fractures are created, thereby removingthe bound naturally-occurring metals from the non-darcy shale formation.The injecting operation may be part of a fracturing operation thatcauses the fractures to occur in the nano-darcy shale formation. Themethod may further include fracturing the nano-darcy shale formation;and wherein the injecting operation occurs after the fracturingoperation causes the fractures to occur in the nano-darcy shaleformation.

These and various other features as well as advantages whichcharacterize the systems and methods described herein will be apparentfrom a reading of the following detailed description and a review of theassociated drawings. Additional features are set forth in thedescription which follows, and in part will be apparent from thedescription, or may be learned by practice of the technology. Thebenefits and features of the technology will be realized and attained bythe structure particularly pointed out in the written description andclaims hereof as well as the appended drawings.

It is to be understood that both the foregoing general description andthe following detailed description are exemplary and explanatory and areintended to provide further explanation of the invention as claimed.

BRIEF DESCRIPTION OF THE DRAWINGS

The following drawing figures, which form a part of this application,are illustrative of described technology and are not meant to limit thescope of the invention as claimed in any manner, which scope shall bebased on the claims appended hereto.

FIG. 1 is an embodiment of a method of well stimulation.

FIG. 2 illustrates a plot of aluminum, barium, manganese, strontium,sulfate; and pH vs. time in samples taken from a horizontal wellcompleted in the Woodford Shale formation and stimulated using thetechnique of FIG. 1 on day 0.

FIG. 3 illustrates a plot of calcium, magnesium and pH vs. time insamples taken from a horizontal well completed in the Woodford Shaleformation from the same experiment as FIG. 2.

FIG. 4 illustrates a plot of iron and pH vs. time in samples taken froma horizontal well completed in the Woodford Shale formation from thesame experiment as FIG. 2.

FIG. 5 illustrates performing the stimulation treatment as part of afracturing operation.

DETAILED DESCRIPTION

Although the techniques introduced above and discussed in detail belowmay be implemented for stimulating any subsurface extractions fromnano-darcy formations, the present disclosure will discuss theimplementation of these techniques in an oil and gas well for thepurpose of extracting hydrocarbons. The reader will understand that thetechnology described in the context of an oil and gas well could beadapted for use with other systems such as water well and solutionmining wells or any other situation in which the permeability of thesubsurface needs to be reduced.

This disclosure describes formulations and methods for stimulating theproduction from wells in nano-darcy shale formations. In one embodiment,the method includes injecting a treatment mixture containing a metalcomplexing agent such as citric acid or EDTA into a nano-darcy shaleformation adjacent to a well at a pressure below the fracture pressureof the formation. A sufficient contact time is allowed and then thetreatment mixture is pumped from the subsurface. This has been shown tostimulate well production in nano-darcy shale formations. Without beingheld to a particular theory, based on an analysis of the extracted spenttreatment fluid it appears that the metal complexing agent binds withnaturally occurring metals in the formation (possibly by forming acomplex with the metals and removing them from the shale), andparticularly divalent metal ions, which are then extracted with thespent fluid. This removal of naturally occurring metals may beincreasing the permeability of the formation in the contact regionadjacent to the well, thereby causing the increased production.

In an alternative embodiment, the well stimulation treatment is appliedas part of the fracturing process. It is anticipated that properintegration of the well stimulation treatment with the fracturingprocess will achieve a better production result than fracturing withoutstimulation. Both embodiments, the fracturing embodiment and thestimulation embodiment done below the fracture pressure of theformation, are described in greater detail below.

The present disclosure relates to a process to sequester and removemetal cations from partially soluble silicon-bearing clay mineralsnaturally present in a subterranean formation. Whether the metallic ionsare present from natural sources in the reservoir rock prior to drillinginto the formation or formed through interactions with drilling,completion, or reservoir stimulation (hydraulic fracturing or acidstimulation) fluids, the use of metal chelating substances to dissolveor disperse materials that are, or can, restrict flow into the well boreis presented as a commercial method to restore or enhance theproductivity of well bores that are restricted with such materials. Forexample, the introduction of hydraulic fracturing fluids and/or acidtreatments that release metal ions through their interaction with theformation materials, such as aluminum, barium, calcium, magnesium,manganese, iron, strontium, boron and other metals or metalloids. Suchmetallic or metalloid ions may form ion complexes with sulfur bearingions such as sulfide and sulfate, hydroxide ions, and silicon bearingions such as silicates; for example calcium magnesium silicate, that mayprecipitate or otherwise form flow restrictions in the porous space ofthe reservoir rock in the well bore. Specifically, metallic ioncomplexes such as aluminum hydroxide, aluminum silicate, calciumhydroxide, calcium magnesium silicate, iron hydroxide, iron silicate,magnesium hydroxide, magnesium silicate, or other metal hydroxide,and/or silicon complexes, or metal sulfide or metal sulfate scales; thatthrough formation of solid or colloidal substances may form restrictionsthat limit the permeability of reservoir rock to producing hydrocarbons.

Introduction and maintenance of a metal-complexing agent into theformation allows for the metals to be bound and subsequently removed.For the purposes of this disclosure, a metal-complexing agent may be anychemical that can bind with a metal regardless of the binding mechanismand includes sequestration agents, reducing agents, chelating agents,ligands porphyrins, pigments, peptides, saccharides and/or nucleicacids. In some embodiments, the metal-complexing agent is a chelatingagent, an alkali metal salt thereof, a non-alkali metal salt thereof, orany combination thereof may be included in the treatment fluidsdescribed herein. In some embodiments, the chelating agent may bebiodegradable. Although use of a biodegradable chelating agent may beparticularly advantageous in some embodiments of the present disclosure,there is no requirement to do so, and, in general, any suitablechelating agent may be used. As used herein, the term “biodegradable”refers to a substance that can be broken down by exposure toenvironmental conditions including native or non-native microbes,sunlight, air, heat, and the like. Use of the term “biodegradable” doesnot imply a particular degree of biodegradability, mechanism ofbiodegradability, or a specified biodegradation half-life.

In some embodiments, A partially soluble or colloidal metal ion complex,such as, for example, calcium magnesium silicate, is solubilized using,for example, one or a combination of the following chelation chemicals(chelating agent): Acetic Acid, Acrylates, Dihydroxymaleic Acid, Saltsof Dihydroxymaleic Acid, EDTA (ethylenediamine tetraacetic acid), Saltsof EDTA, erythorbic acid, erythroboric acid, Formic Acid,Gluconodeltalactone, GLDA (glutamic acid N,N-diacetic acid), Salts ofGLDA, HEDTA (hydroxyethylenediamine triacetic acid), Salts of HEDTA,HEIDA (disodium ethanoldiglycine), Salts of HEIDA, MGDA (methylglycineN,N-diacetic acid), Salts of MGDA, NTA (nitriolotriacetic acid), OrganicMetal Complexers, Phosphonic Acid, Polyacrylic Acid and notably CitricAcid in an amount sufficient to sequester at least a portion of anymetal compounds and there by dissolve or disperse materials that canrestrict the flow path to the well bore and the overall permeability ofthe well bore and reservoir rock system. It should be understood thatalthough chelation chemical(s) (chelating agent(s), chelator(s)) havebeen provided herein by way of example, any chelation chemical may beutilized in accordance with the present process, so long as thechelation chemical functions in accordance with the present disclosureas described herein.

In some embodiments, suitable chelating agents may include commonchelating agent compounds such as, for example,ethylenediaminetetraacetic acid (EDTA), propylenediaminetetraacetic acid(PDTA), nitrilotriacetic acid (NTA),N-(2-hydroxyethyl)ethylenediaminetriacetic acid (HEDTA),diethylenetriaminepentaacetic acid (DTPA), hydroxyethyliminodiaceticacid (HEIDA), cyclohexylenediaminetetraacetic acid (CDTA),diphenylaminesulfonic acid (DPAS),ethylenediaminedi(o-hydroxyphenylacetic) acid (EDDHA), glucoheptonicacid, gluconic acid, oxalic acid, malonic acid, succinic acid, glutaricacid, adipic acid, pimelic acid, suberic acid, azelaic acid, sebacicacid, phthalic acid, terephthalic acid, aconitic acid, carballylic acid,trimesic acid, isocitric acid, citric acid, any salt thereof, anyderivative thereof, and the like. It is to be noted that NTA may beconsidered to be a biodegradable compound, but it may have undesirabletoxicity issues.

In some embodiments, suitable chelating agents may include biodegradablechelating agents such as, for example, glutamic acid diacetic acid(GLDA), methylglycine diacetic acid (MGDA), β-alanine diacetic acid((β-ADA), ethylenediaminedisuccinic acid, S,S-ethylenediaminedisuccinicacid (EDDS), iminodisuccinic acid (IDS), hydroxyiminodisuccinic acid(HIDS), polyamino disuccinic acids,N-bis[2-(1,2-dicarboxyethoxy)ethyl]glycine (BCA6),N-bis[2-(1,2-dicarboxyethoxy)ethyl]aspartic acid (BCA5),N-bis[2-(1,2-dicarboxyethoxy)ethyl]methylglycine (MCBA5),N-tris[(1,2-dicarboxyethoxy)ethyl]amine (TCA6), N-methyliminodiaceticacid (MIDA), iminodiacetic acid (IDA), N-(2-acetamido)iminodiacetic acid(ADA), hydroxymethyl-iminodiacetic acid, 2-(2-carboxyethylamino)succinic acid (CEAA), 2-(2-carboxymethylamino) succinic acid (CMAA),diethylenetriamine-N,N″-disuccinic acid,triethylenetetramine-N,N″′-disuccinic acid,1,6-hexamethylenediamine-N,N′-disuccinic acid,tetraethylenepentamine-N,N″″-disuccinic acid,2-hydroxypropylene-1,3-diamine-N,N′-disuccinic acid,1,2-propylenediamine-N,N′-disuccinic acid,1,3-propylenediamine-N,N′-disuccinic acid,cis-cyclohexanediamine-N,N′-disuccinic acid,trans-cyclohexanediamine-N,N′-disuccinic acid,ethylenebis(oxyethylenenitrilo)-N,N′-disuccinic acid, glucoheptanoicacid, cysteic acid-N,N-diacetic acid, cysteic acid-N-monoacetic acid,alanine-N-monoacetic acid, N-(3-hydroxysuccinyl) aspartic acid,N-[2-(3-hydroxysuccinyl)]-L-serine, aspartic acid-N,N-diacetic acid,aspartic acid-N-monoacetic acid, any salt thereof, any derivativethereof, or any combination thereof.

In an alternative embodiment, the metal-complexing agent may be asuitable sequestering agent such as polysuccinimide, polyaspartic acid,and polymers, oligomers, chains or block-copolymers of the twenty twoessential amino acids containing metal complexing groups such ascarboxylic acids, phosphonic acids, sulfonic acids and boronic acids.

In one embodiment, the chelating agent is provided between about 0.05%weight volume to about 60% weight volume. However, any suitable rangemay be used including from 1% to 40%, and between 2% and 20%. In someembodiments, the amount of chelating agent may be even higher as somechelating agents may be provided with additives as described in greaterdetail below.

The well stimulation mixture can contain the metal complexing agent aswell as multiple chemical additives as desired. The additives mayinclude biocide, scale inhibitor, clay control additive, oxygenscavenger and surfactant that assist fluid recovery. To keep thefracturing treatments affordable, only minimal amounts of theseadditives are used. Each additive is normally liquid-based and ismetered separately into the treatment fluid and mixed with water andother additives in the blender. The blender includes a 5- to 15-barreltub with agitation devices. The additive concentrations are commonlyexpressed in parts per million (ppm) or as gallons of additive per 1000gallons of water (abbreviated as gallons per thousand or gpt). Theadditives typically are composed of a chemical that provides the desiredfunction such as scale inhibition and a solvent, commonly water, alcoholor oil.

Another additive that may be used is a corrosion inhibitor. Corrosioninhibitors reduce corrosion of the well components. In an embodiment,quaternary ammonium compounds typically referred to as quaternary aminesare used as a corrosion inhibitor in trace amounts to 2,000 ppm.However, any suitable corrosion inhibitor may be used in any amount asdesired. Other examples of possible corrosion inhibitors includequaternary amine compounds commonly used for protection of metal in thepresence of high or low pH and/or dissolved oxygen bearing fluids, suchas Flex Chem FC-181 and many other similar formulations used in wellmaintenance activities. Quaternary ammonium compounds, acetylenicalcohols, amide and oxylalkylated alcohols, quinoline quaternaryammonium alkyl amine salts and surfactants, nonyl phenol surfactants,alkyl thioamides, oxyalkylated phenols, alkyl pyridine benzyl quaternaryammonium chloride, benzyl quaternary ammonium chloride, aliphaticamines, cocoamine diquaternary ammonium chloride, imadazoline,polyamide, modified amido polyamine, alkylamidomine, amido imadazoline,alkyl phosphate ester, potassium salt of a glycol phosphate ester, aminesalt of poly-phosphate ester, tallow diamine ethoxylate, polyacid, aminesalt of polyphosphonic acid, organic acid-amine salt, crude dimerizedfatty acids or tall oil dimer-trimer acids.

Surfactants such as sodium lauryl sulfate and many other surfactantmaterials that could be selected based on their compatibility with theother materials in the chelating solution and pH of the final solution.

Another additive that may be used is a biocide. For example, in anembodiment trace amounts to 5,000 ppm tributyl tetradecyl phosphoniumchloride (TTPC) may be used as a biocide. Any suitable biocide may beused in any amount as desired. Biocidal agents could includeglutaraldehyde, quaternary amine compounds such as alkyl dimethyl benzylammonium chloride (ADBAC), sodium chlorite (which would generatechlorine dioxide in-situ), TTPC, isothiazolin compounds, thione basedcompounds, and many other agents approved for use in the wellmaintenance activities. Other examples of possible biocides includechlorine dioxide, didecyldimethyl ammonium chloride (DDAC) andbrominated propionamide.

Dispersing agents such as Dow Acumer 5000 or Versaflex Si to enhance theremoval of colloidal silicon bearing materials and many other dispersingagents that could assist with recovering colloidal material residue fromthe well bore.

Another additive that may be used is a colloidal silica depositioninhibitor. The use of a colloidal silica deposition inhibitor, sometimesalso referred to as amorphous silica control compound, prevents silicascale precipitation within the wells during the treatment process. Oneexample of a colloidal silica deposition inhibitor is an aqueoussolution of organic additive based on phosphino carboxylic acidcopolymer, a commercial version of which is sold under the trademarkGEOGARD SX. Any suitable colloidal silica deposition inhibitor may beused. Other examples of possible colloidal silica deposition inhibitorsinclude such materials as phosphate, phosphate ester, or phosphonatecompounds; polymaleic, or acrylate compounds such as polyacrylic acidscale inhibitors commonly used for such applications in well maintenanceactivities.

Another additive that may be used is a mutual solvent. Mutual solventsare soluble in oil, water and acid-based mixtures and may be used in arange of applications, such as removing heavy hydrocarbon deposits,controlling the wettability of contact surfaces before, during or aftera stimulation treatment, and preventing or breaking emulsions. Acommonly used mutual solvent is ethylene glycol monobutyl ether,generally known as EGMBE or 2-butoxy ethanol. Any suitable mutualsolvent may be used. Other examples of possible mutual solvents includecompounds such as ethylene glycol monobutyl ether or FCS-280 or othercompounds commonly used for such applications in well maintenanceactivities.

Acid may also be used as an additive in order to control the pH of thetreatment mixture. In an embodiment hydrochloric acid may be used fromtrace amounts to about 30% by weight. Any suitable acid may be used asneeded. Other examples of possible acids include aqua regia, arsenicacid, boric acid, carbonic acid, chloric acid, chromic acid,fluoroantimonic acid, fluoroboric acid, fluorosulfuric acid, fulminicacid, hexafluorophosphoric acid, hexafluorosilicic acid, hydrobromicacid, hydrofluoric acid, hydrogen iodide, hypochlorous acid,hypofluorous acid, hypophosphoric acid, iodic acid, nitric acid,nitrosyl-O-hydroxide, nitrous acid, orthocarbonic acid, perchloric acid,permanganic acid, perrhenic acid, pertechnetic acid, phosphoric acid,silicic acid, sulfuric acid, thiocyanic acid, titanic acid, tungsticacid or xenic acid.

In some wells, well stimulation using the novel treatment mixturesdesigned herein may be made more cost efficient by alternating theinjection of the treatment mixture with the injection of a divertingmaterial. Many wells have high volume sections within the well flowpaths that are referred to as fluid thief zones in that they represent avolume that must be filed during the treatment process but the fluid inthat zone is ineffective at its task (in this case complexing with metalcations in the nano-darcy formation). To address this, a divertingmaterial such as particles of polylactic acid in a brine mixture may beused. Diverting materials are designed to take up larger volumes withoutinterfering with the delivery of treatment chemicals to the targetzones. Diverting materials are relatively inert with respect to thetreatment chemicals and are also designed to allow easy passage of thetreatment chemicals around volumes that they occupy. In addition, manydiverting materials are designed to breakdown and be easily recoverableafter some period of time such as days or weeks.

Diverting materials and mixtures other than particles of polylactic acidin a brine mixture may also be used. Diverting agents such as benzoicacid flakes, polylactic acid, solid or water soluble ball sealers, rocksalt, encapsulated solid chelators, etc., other diverting agents. Forexample, mixtures using products consisting of various polymers blendedwith waxes and other solid hydrocarbons polymers blended with waxes andother solid hydrocarbons have been used as diverting material. Divertingmaterials are designed to be relatively inert with respect to thetreatment chemicals and are also designed to allow easy passage of thetreatment chemicals.

In an embodiment, a stimulation program may include alternating betweeninjecting an amount of treatment mixture, followed by injecting anamount of a diverting mixture until such time as the well pressureachieves a target pressure, such as a pre-determined target pressure,the fracture pressure for the formation or a threshold amount above orbelow the pre-determined fracture pressure from the formation calculatedbased on the fracture pressure.

FIG. 1 illustrates one such stimulation program, in this case done belowthe fracture pressure of the formation. In the program 100, thetreatment mixture is obtained in a provide treatment mixture operation102. The treatment mixture may be made or completed on site in a batchprocess or an amount of treatment mixture may be brought to the siteprior to the stimulation of the well. Any of the embodiments of thetreatment mixture described above may be used.

A provide diverting mixture operation 104 is also performed in which adiverting mixture is either generated at the site prior to use or amixture is brought to the site pre-made. Any diverting mixture asdescribed above may be used. This operation 104, is also optional andmay not be needed if it is determined that there will be relativelylittle lose to thief zones of the treatment mixture during the treatmentprocess.

Next, the treatment mixture and the diverting mixture (if any) areinjected in an injection operation 106. In an embodiment, the twomixtures are alternately injected in alternating injection operation106. As described above, predetermined amounts of the mixtures may bealternately injected or the injection amounts may be varied. In anembodiment, for example, the injection operation alternately injects 150barrels of treatment mixture and 150 barrels of diverting mixture.

In one embodiment, injection continues until such time as the wellpressure achieves a target pressure. The target pressure may be apre-determined target pressure based on knowledge of the operator.Alternatively, the target pressure may be the fracture pressure for theformation or a threshold amount above or below the fracture pressurefrom the formation. Any suitable technique such as the Leak-off test maybe used to determine fracture pressure.

Upon reaching the target pressure, a well shut in operation 108 isperformed. In the shut in operation 108, the well is closed and thetreatment mixture is trapped in the well.

The well is then maintained in the shut in state in a maintain shut inoperation 110. This provides contact time for the treatment mixtureallowing the treatment chemicals to react with the shale formation andbind some of the natural metals to the treatment mixture. During thisperiod, the pressure may slowly decrease and the pH may change due toreactions occurring in the subsurface. The contact time provided may beany amount from 1 minute to 100 days. However, it appears that 1 to 3days may be preferable. Other examples of acceptable ranges of contacttimes include: from 3 hours to 7 days; from 6 hours to 5 days; from 12hours to 45 days; from 18 hours to 3 days and from 1 to 2 days. Too longor too short a contact time may result in lowered performance. Too shorta time may not allow sufficient time for the treatment mixture tocomplex with the naturally occurring metals in the formation. Too long acontact time may result in bound metals precipitating within the well orformation before they can be removed with the spent treatment mixture.It is anticipated that the optimum time may need to be determinedempirically for each formation or even each depth or region of aformation. In this case, determining the contact time may be consideredan additional step in the stimulation process. This step may includetesting multiple wells at different contact times, using a downholemonitoring device or other mechanism to determine when sufficientsolubilizing of the formation metals has been achieved or by someex-situ method such as by calculation or lab testing of formationmaterials.

The method ends with the extraction of the treatment mixture in amixture removal operation 112. In the removal operation 112, the wellopened and the mixtures are pumped out of the well. The mixtures willinclude bound metals from the subsurface. Again, without being held to aparticular theory, based on an analysis of the extracted treatmentmixtures and laboratory testing it appears that the metal complexingagent is forming metal complexes and/or binding with naturally occurringmetals in the formation, and particularly divalent metal ions, which arethen extracted with the spent treatment mixture. This removal ofnaturally occurring metals may be increasing the permeability of theformation in the contact region adjacent to the well, thereby causingthe increased production of the well after the stimulation using thetechniques described above.

FIG. 5 illustrates performing the stimulation treatment as part of afracturing operation. In the process of hydraulic fracturing, fluid isinjected into the well at a pressure that induces fractures in thereservoir rock. Pumping is continued after the fractures are initiated,which causes the fractures to propagate and widen sufficiently to allowa proppant material to enter the fractures. Stages of fluids ofdifferent composition are injected sequentially to induce, propagate andprop the fractures. One example of an injection sequence is:

-   -   1. An initial acid (sometimes referred to as the “pre-pad        stage”), typically containing hydrochloric acid, to clear the        wellbore and perforations.    -   2. A conditioning (or “pad stage”) to open the fractures, and        containing chemicals to condition fluid pathways.    -   3. A proppant stage which carries the proppant material into the        opened fractures, and normally containing a polymer to increase        the proppant carrying capacity.    -   4. A flushing stage to clean excess chemicals and proppant from        the wellbore.        The above sequence and/or individual steps, or stages as they        are sometimes called below, may be repeated as needed or        desired.

In the fracturing process embodiment of the well stimulation treatment,a stimulation treatment mixture containing a metal complexing agent suchas citric acid or EDTA could be placed in any of the stages, or as anadditional stage anywhere in a fracturing injection sequence, such asthe one described above. The placement within the injection sequence ofthe treatment mixture injection would affect where the treatment goeswithin the formation and, therefore, control the resulting effects onthe formation.

In the fracturing process embodiment of the well stimulation treatment,a stimulation treatment mixture containing a metal complexing agent suchas citric acid or EDTA could be placed in any of the stages, or as anadditional stage anywhere in a fracturing injection sequence, such asthe one described above. The placement within the injection sequence ofthe treatment mixture injection would affect where the treatment goeswithin the formation and, therefore, control the resulting effects onthe formation.

For example, injecting the stimulation treatment mixture before the padstage would make the stimulation treatment mixture contact the formationduring the stage that opens the fracture and, thus, make it the firstfluid to contact the surface of the newly-induced fractures. Assumingfluids, including the treatment mixture, from the early stages leaks offinto the formation, placing the stimulation treatment mixture before thepad stage would allow the treatment mixture to leak off into theformation matrix before other chemicals in the pad stage affect thefracture face.

As another example, placing the stimulation treating mixture in theproppant stage would allow the chemicals in the pad stage to affect thecontact of the fracture face before the treatment mixture contacts thefracture face. If the chemicals in the pad stage alters the rock alongthe fracture face it could potentially affect the penetration of thetreatment mixture. In the extreme case, if chemicals in the pad stageprevent fluid leakoff it could potentially prevent the stimulationtreatment mixtures from penetrating into the formation matrix.

If a goal is to sequester ions from reservoir rock matrix (e.g., toincrease the permeability of the rock near the fracture), it may bedesirable to inject the treatment mixture early in the sequence to getmaximum penetration. On the other hand, if the goal is to sequester ionsfrom other sources, such as displaced or introduced ions, it may bedesirable to place the treatment later in the sequence. Thus, theinjection sequence can be tailored to specific goals depending on theconditions at the wellhead and in the formation. In an embodiment,determination of the optimum stage for including injection At this timean optimum treatment mixture placement in combination with hydraulicfracturing has not been experimentally determined and we would like tosecure as much treatment design flexibility as possible.

Fluids used in all stages of well fracturing contain chemical additivesthat may include acids, hydrocarbons, gums, polymers, solids,surfactants, scale inhibitors, disinfectants, etc. In the currentstate-of-the-art the formulations and placements are designed tofacilitate and optimize the hydraulic pumping without the design or aimof treating the hydrocarbon-bearing formations with metal complexingagents.

Acids, commonly hydrochloric, citric, etc., may be added in initialstages to clean wellbore debris such as cement from fluid paths andcontrol iron released from the steel well components by the harshchemicals, and the formulations and volumes are designed to be mostlyspent within the wellbore with preferably no entry into the fracture, asthat would be wasted and, therefore, cost inefficient. Additionalchemistries are formulated to further facilitate the hydraulic pumpingby facilitating flow and proppant placement with minimal chemical effecton the formation past the fracture face.

Loss of fluid into the formation during hydraulic fracturing decreaseshydraulic efficiency. In applications where fluid loss may affecthydraulics of the fracturing operation additives such as divertingmaterials, polymers, particulates, fine sand, hydrocarbons, etc., arecommonly added to fracturing fluids to minimize leakoff of fracturingfluids into the formation and improve fluid hydraulic efficiency. Inmore permeable formations some initial fluid may spurt into theformation matrix before a barrier, or wall cake, is formed by the fluidadditives, which slows or prevents further leakoff. In less permeableformations the fluid additives may prevent significant spurt fromoccurring.

Chemical interactions of fluid formulations during fracturing may beaffected by placement and staging of specific formulations, otherchemistries and sequential placement of the other chemistries. Chemicalformulations in early fluid stages that may spurt into the formationpotentially have more access to the formation matrix than later stagesthat enter the fracture after a wall cake is formed, and if suchchemical formulations were applied in a fluid stage that did not containadditional additives the chemical interaction of the chemicalformulations with the formation matrix could potentially be affectedless by the subsequent additives.

The stimulation treatment can be adapted to treat hydrocarbon-bearingformations with metal complexing agents. The chemical formulations areas described earlier during fracturing. The fracturing embodiments mayinclude sequencing the well stimulation mixture in combination withhydraulic fracturing in ways to treat the formation differently.

In one embodiment, the well stimulation mixture could be formulated andinjected in an initial stage that opens the fracture and contacts theformation before additional chemical additives. There are a number ofways this could be achieved. For example, a well stimulation mixture ofsufficient volume to propagate through the induced fracture and contactthe formation before a potential barrier or wall cake is formed could beinjected between the pre-pad and pad stages or the pre-pad and/or padstage could be modified with chemical amendments and/or design toachieve formation treatment.

In another embodiment, the well stimulation mixture could be formulatedand injected in a stage containing a diverting or leakoff-minimizingmaterial. Initially a limited amount of treatment mixture might contactthe formation as wall cake is formed and treatment mixture has initialaccess to diverting material and wall cake inner face, outer face andwall cake matrix. In such a case the treatment of the formation might beinfluenced by other chemistries in the inclusive and/or prior stage(s).This method of treatment could be applied by injecting a new stage ormodifying a stage containing other materials and formulations.

In another embodiment, the well stimulation mixture could be formulatedand injected in post-diversion/wall cake stage such as a proppant stage.In this case immediate access of the stimulation treatment mixture isprimarily limited to outer face of wall cake and other stagematerials/chemicals. Treatment of the formation might be influenced byother chemistries of prior stages and might be delayed by some amount oftime for the stimulation treatment mixture to penetrate the divertingmaterial/wall cake. This method of treatment could be applied byinjecting a new stage or modifying a stage containing other materialsand formulations.

In another embodiment, the well stimulation mixture could be formulatedand injected in a trailing or flushing stage at a pressure below thefracture pressure as described with reference to FIG. 1. Treatment ofthe formation might be influenced by other chemistries of prior stagesand might be delayed by some amount of time for the treatment mixture topenetrate the diverting material/wall cake. This method of treatmentcould be applied by injecting a new stage or modifying a stagecontaining other materials and formulations.

Turning now to the embodiment of FIG. 5, a well stimulation treatmentprogram as part of a fracturing process is described in greater detail.In the program 500, the treatment mixture is obtained in a providetreatment mixture operation 502. The treatment mixture may be made orcompleted on site in a batch process or an amount of treatment mixturemay be brought to the site prior to the stimulation of the well. Any ofthe embodiments of the treatment mixture described above may be used.

A provide fracturing fluids operation 504 is also performed in which thevarious fracturing fluids necessary for the fracturing operation areeither generated at the site prior to use or brought to the sitepre-made. Fracturing operations and the various fracturing fluids foreach stage of the fracturing operation are known in the art.

Next, a combined fracturing/stimulation operation 506 is performed. Asdescribed above, different embodiments are possible depending upon whenduring the fracturing process the well stimulation mixture isincorporated.

FIG. 5 specifically illustrates the embodiment in which the wellstimulation mixture is injected in the initial stage of the fracturingoperation. In the embodiment illustrated, a pre-pad stage 508 isperformed, as described above, to clear the wellbore and perforations.This may include injecting an acid or other pre-pad formulation.

The pre-pad stage 508 is then followed by a stimulation injectionoperation 510. In this operation 510, the stimulation treatment mixtureis injected at a pressure above the fracturing pressure of the formationin order to create the initial fractures.

A proppant stage 512 is then performed in which proppant material isinjected and forced into the opened fractures. In an embodiment, theinjected proppant mixture may include polymers and other chemicals toincrease the proppant carrying capacity and reduce the pressure neededto inject the proppant.

Next, a flushing stage 514 is performed in which excess chemicals andproppant from the wellbore. In this embodiment, spent well stimulationtreatment mixture, bound with metals from the subsurface formation, willalso be recovered. It is believed, based on the laboratory results andthe results observed from stimulation below the fracturing pressure,that the combined fracturing/stimulation embodiments described abovewill result in a higher production rate for the well that would beachieved without the use of the stimulation treatment mixture. Again,without being held to a particular theory, this is presumably because ofthe affect the stimulation treatment mixture has on the formation. Bybinding with naturally occurring metals in the formation, andparticularly divalent metal ions, it is believed that the permeabilityof the formation near the fractures is increased, thereby causing theincreased production of the well that would otherwise be observed.

As discussed above, the entire process may be repeated until sufficientfracturing has been achieved. Other embodiments of the method 500 arepossible. In addition to changing any of the specific components of themixtures as described above, changes to when and how the mixtures areproduced and injected may be made without departing from the teaching ofthis disclosure.

EXAMPLES Example 1

A laboratory analysis was performed in which an embodiment of thetreatment mixture was mixed with a sample of nano-darcy shale materialobtained from well cuttings of a well drilled into the Barnett ShaleFormation, a nano-darcy shale formation. The embodiment of the treatmentmixture was as follows: 10% by weight citric acid; 2000 ppm ofquaternary amine; 5000 ppm of TTPC; 10000 ppm of GEOGARD SX colloidalsilica deposition inhibitor; 20 gpt of 2-butoxy ethanol; and 10% byweight hydrochloric acid in an aqueous mixture.

The Barnett Shale material was mixed with the embodiment described aboveand allowed to soak for 96 hours at 179 degrees F. An analysis ofvarious metals was performed by Inductively Coupled Plasma (ICP) ontreatment mixture removed from the shale material after the end of the96 hours. The results, provided below, show that the treatment mixtureis effective at binding with metals naturally occurring in thenano-darcy shale formation.

Aluminum Arsenic Barium Boron Calcium Iron Potassium mg/L 710.8 1.9 2.037.3 21.7 2,808 192.6 mg/Kg 31,796.0 85.0 89.5 1,668.53 970.7 125,6098615.5 Magnesium Manganese Sodium Silicon Strontium Molybdenum Antimonymg/L 68.2 53.1 30.8 8.9 0.8 <0.3 10.8 mg/Kg 3,050.8 2,375.3 1,377.8398.1 35.8 <13.4 483.1

Example 2

A laboratory analysis was performed in which an embodiment of thetreatment mixture was mixed with a sample of nano-darcy shale materialobtained from well cuttings of a well drilled into the Cana WoodfordShale Formation, a nano-darcy shale formation. The embodiment of thetreatment mixture was as follows: 10% by weight citric acid; 2000 ppm ofquaternary amine; 5000 ppm of TTPC; 10000 ppm of GEOGARD SX colloidalsilica deposition inhibitor (aqueous solution of organic additive basedon phosphino carboxylic acid copolymer); 20 gpt of 2-butoxy ethanol; and10% by weight hydrochloric acid in an aqueous mixture.

A 4.471 g sample of the Cana Woodford Shale material was mixed with 200ml of the embodiment described above and allowed to soak for 96 hours at179 degrees F. An ICP analysis of various metals was performed ontreatment mixture removed from the shale material after 1 hour andanother at the end of the 96 hours. The results, provided below, showthat the treatment mixture is effective at binding with metals naturallyoccurring in the nano-darcy shale formation.

Time Removed Aluminum Antimony Arsenic Barium Boron Calcium IronTothours mg/L mg/L mg/L mg/L mg/L mg/L mg/L 1 102 0.210 0.190 2.70 6.87 344150 96 2,994 6.165 5.578 79.26 201.67 10,098 4,403 Time RemovedPotassium Magnesium Manganese Molybdenum Silicon Sodium Strontium hoursmg/L mg/L mg/L mg/L mg/L mg/L mg/L 1 49.8 233 4.35 0.450 211 20.9 3.7796 1,461.9 6,840 127.70 13.210 6,194 613.5 110.67

Example 3

An experiment was performed in a well located in the nano-darcy Woodfordshale formation in Canadian County, Oklahoma. In this experiment thefollowing 1200 barrel treatment mixture was used: 10% by weight citricacid; 2000 ppm of quaternary amine; 5000 ppm of TTPC; 10000 ppm ofGEOGARD SX colloidal silica deposition inhibitor (aqueous solution oforganic additive based on phosphino carboxylic acid copolymer); and 20gpt of 2-butoxy ethanol. A diverting material was also used comprisingdifferent sizes of poly lactic acid particles in a 10.2 pound/gallonbrine mixture to create a diverting mixture. The treatment and divertingmixtures were alternately injected into the well in amounts of 150barrels each until completion. After completion the well was shut in andthe treatment mixture maintained in the well for 4 days.

The treatment mixture was then extracted and analyzed for metal contentincluding aluminum, iron, magnesium and silicon. The following table isa list of results of the analysis.

Rw. Al Fe Mg Si Sample #: Day: Time: pH: Sp. Gr. Ohm-M mg/L mg/L mg/Lmg/L Pre-Job  9:00 7.07 1.0049 0.650 0.18 <0.18 5.28 41.4 1 1 12:00 7.381.0050 0.800 118 1,399 586 26 2 2 14:00 6.19 1.0250 0.340 300 2,3041,270 104 3 2 15:00 6.28 1.0262 0.340 303 2,156 1,294 116 4 2 16:00 6.241.0247 0.340 295 1,926 1,271 110 5 2 18:00 6.25 1.0250 0.320 333 2,0171,457 98 6 2 19:00 6.17 1.0258 0.320 333 1,846 1,389 107 7 2 20:00 6.261.0251 0.315 319 1,746 1,366 87 8 2 22:00 6.23 1.0263 0.330 321 1,7301,361 91 9 3  0:00 6.30 1.0250 0.320 330 1,593 1,416 92 10 3  2:00 6.331.0247 0.340 331 1,468 1,396 91 11 3  4:00 6.25 1.0249 0.300 372 1,7251,601 110 12 3  6:00 6.25 1.0271 0.310 347 1,567 1,496 82 13 3  8:006.34 1.0277 0.320 376 1,673 1,593 69 14 3 10:00 6.24 1.0279 0.320 3791,668 1,621 72 15 3 12:00 6.20 1.0280 0.310 391 1,703 1,714 81 16 314:00 6.19 1.0301 0.295 403 1,726 1,744 72 17 3 16:00 6.20 1.0307 0.300418 1,772 1,805 85 18 3 18:00 6.18 1.0310 0.280 440 1,816 1,849 89 19 320:00 6.16 1.0317 0.295 434 1,750 1,872 114 20 3 22:00 6.22 1.0320 0.295438 1,765 1,886 74 21 4  0:00 6.16 1.0320 0.290 434 1,754 1,857 104 22 4 2:00 6.20 1.0314 0.300 481 1,828 1,975 89 23 4  4:00 6.23 1.0312 0.280463 1,766 1,918 106 24 4  6:00 6.16 1.0315 0.280 448 1,675 1,873 111 254  8:00 6.37 1.0310 0.280 464 1,714 1,887 58 26 4 10:00 6.32 1.03060.270 498 1,782 1,933 67 27 4 12:00 6.34 1.0303 0.275 478 1,734 1,886 7228 4 14:00 6.33 1.0300 0.280 508 1,785 1,951 106 29 4 16:00 6.31 1.03040.290 490 1,657 1,844 82 30 4 18:00 6.35 1.0300 0.295 492 1,686 1,867 6131 5 12:00 6.35 1.0299 0.300 529 1,705 1,895 66 32 6 12:00 6.35 1.03000.300 421 1,256 1,486 47 33 7 12:00 6.36 1.0300 0.300 436 1,276 1,489 7234 8 12:00 6.38 1.0294 0.300 464 1,636 1,794 70 35 9 11:00 6.40 1.02950.300 414 1,206 1,440 81 36 10 10:30 6.39 1.0300 0.300 470 1,716 1,86371 37 11 10:00 6.54 1.0240 0.290 414 1,226 1,402 68 38 12  9:00 6.591.0230 0.285 364 1,090 1,239 56 39 13 10:00 6.51 1.0195 0.305 241 803888 95 40 14 17:30 6.50 1.0215 0.300 400 1,194 1,401 80 41 15 13:30 6.541.0219 0.299 314 951 1,110 89 42 16 12:00 6.52 1.0200 0.300 252 810 94298 43 17 15:30 6.52 1.0205 0.300 334 1,016 1,212 113 44 18 10:30 6.531.0195 0.300 252 807 964 101 45 19 10:00 6.53 1.0200 0.305 233 749 87292 46 20 12:00 6.44 1.0183 0.305 167 625 670 86 47 21 11:00 6.50 1.01580.305 242 793 916 100 48 22 13:30 6.45 1.0175 0.310 225 760 861 94 49 2312:30 6.38 1.0171 0.310 232 784 917 105 50 24 12:30 6.60 1.0164 0.310189 669 769 93

In the experiment, after the shut in period, the well was pumped andsamples of extracted flowback liquids were obtained and analyzed forvarious constituents over a 24 day period. The data shows a trendsimilar to the laboratory analyses of a high initial recovery of metalsthat trails off significantly over the first 3-7 days.

In addition, the subsequent well production rates were determined andcompared to the production rate of the well prior to stimulation. Thecomparison showed that the gas production showed an 11 to 1 improvementin product rates. The liquid hydrocarbon production showed a 5 to 1improvement after stimulation.

Example 4

FIGS. 2 through 4 illustrate some results obtained from the use ofembodiments of the stimulation treatment mixtures described above.

FIG. 2 illustrates a plot of aluminum, barium, manganese, strontium,sulfate; and pH vs. time in samples taken from flowback out of ahorizontal well completed in the Woodford Shale formation.

FIG. 3 illustrates a plot of calcium, magnesium and pH vs. time insamples taken from a horizontal well completed in the Woodford Shaleformation from the same experiment as FIG. 2.

FIG. 4 illustrates a plot of iron and pH vs. time in samples taken froma horizontal well completed in the Woodford Shale formation.

Unless otherwise indicated, all numbers expressing quantities ofingredients, properties such as molecular weight, reaction conditions,and so forth used in the specification and claims are to be understoodas being modified in all instances by the term “about.” Accordingly,unless indicated to the contrary, the numerical parameters set forth inthe following specification and attached claims are approximations thatmay vary depending upon the desired properties sought to be obtained.

As used herein, “about” refers to a degree of deviation based onexperimental error typical for the particular property identified. Thelatitude provided the term “about” will depend on the specific contextand particular property and can be readily discerned by those skilled inthe art. The term “about” is not intended to either expand or limit thedegree of equivalents which may otherwise be afforded a particularvalue. Further, unless otherwise stated, the term “about” shallexpressly include “exactly,” consistent with the discussions regardingranges and numerical data. Concentrations, amounts, and other numericaldata may be expressed or presented herein in a range format. It is to beunderstood that such a range format is used merely for convenience andbrevity and thus should be interpreted flexibly to include not only thenumerical values explicitly recited as the limits of the range, but alsoto include all the individual numerical values or sub-ranges encompassedwithin that range as if each numerical value and sub-range is explicitlyrecited. As an illustration, a numerical range of “about 4 percent toabout 7 percent” should be interpreted to include not only theexplicitly recited values of about 4 percent to about 7 percent, butalso include individual values and sub-ranges within the indicatedrange. Thus, included in this numerical range are individual values suchas 4.5, 5.25 and 6 and sub-ranges such as from 4-5, from 5-7, and from5.5-6.5; etc. This same principle applies to ranges reciting only onenumerical value. Furthermore, such an interpretation should applyregardless of the breadth of the range or the characteristics beingdescribed.

Notwithstanding that the numerical ranges and parameters setting forththe broad scope of the disclosure are approximations, the numericalvalues set forth in the specific examples are reported as precisely aspossible. Any numerical value, however, inherently contain certainerrors necessarily resulting from the standard deviation found in theirrespective testing measurements.

It will be clear that the systems and methods described herein are welladapted to attain the ends and advantages mentioned as well as thoseinherent therein. Those skilled in the art will recognize that themethods and systems within this specification may be implemented in manymanners and as such is not to be limited by the foregoing exemplifiedembodiments and examples. In other words, functional elements beingperformed by a single or multiple components, in various combinations ofhardware and software, and individual functions can be distributed amongsoftware applications at either the client or server level. In thisregard, any number of the features of the different embodimentsdescribed herein may be combined into one single embodiment andalternate embodiments having fewer than or more than all of the featuresherein described are possible.

It will be clear that the systems and methods described herein are welladapted to attain the ends and advantages mentioned as well as thoseinherent therein. Those skilled in the art will recognize that themethods and systems within this specification may be implemented in manymanners and as such is not to be limited by the foregoing exemplifiedembodiments and examples. In this regard, any number of the features ofthe different embodiments described herein may be combined into onesingle embodiment and alternate embodiments having fewer than or morethan all of the features herein described are possible.

While various embodiments have been described for purposes of thisdisclosure, various changes and modifications may be made which are wellwithin the scope of the present disclosure. Numerous other changes maybe made which will readily suggest themselves to those skilled in theart and which are encompassed in the spirit of the disclosure.

What is claimed is:
 1. A method for stimulating a well in a nano-darcyshale formation comprising: providing a treatment mixture containingbetween about 0.1% and 95% by weight metal complexing agent at a pH ofbetween about 0 and 10; injecting the treatment mixture into the well ata pressure less than a fracture pressure of the nano-darcy shaleformation until at least some of the treatment mixture contacts thenano-darcy shale formation; maintaining the treatment mixture in contactwith the nano-darcy shale formation for a contact time of between about1 minute to 100 days, thereby allowing the metal complexing agent tobind with at least some naturally-occurring metals contained within thenano-darcy shale formation; and removing the treatment mixture from thewell after the contact time, thereby removing the boundnaturally-occurring metals from the non-darcy shale formation andthereby improving the hydrocarbon production of the well relative to thehydrocarbon production immediately prior to performance of the method.2. The method of claim 1 wherein the metal complexing agent is citricacid.
 3. The method of claim 1 wherein the metal complexing agent isethylenediaminetetraacetic acid (EDTA).
 4. The method of claim 1 whereinthe metal complexing agent is acetic acid.
 5. The method of claim 1wherein the metal complexing agent includes at least one ofethylenediaminetetraacetic acid (EDTA), propylenediaminetetraacetic acid(PDTA), nitrilotriacetic acid (NTA),N-(2-hydroxyethyl)ethylenediaminetriacetic acid (HEDTA),diethylenetriaminepentaacetic acid (DTPA), hydroxyethyliminodiaceticacid (HEIDA), cyclohexylenediaminetetraacetic acid (CDTA),diphenylaminesulfonic acid (DPAS),ethylenediaminedi(o-hydroxyphenylacetic) acid (EDDHA), glucoheptonicacid, gluconic acid, oxalic acid, malonic acid, succinic acid, glutaricacid, adipic acid, pimelic acid, suberic acid, azelaic acid, sebacicacid, phthalic acid, terephthalic acid, aconitic acid, carballylic acid,trimesic acid, isocitric acid, citric acid, or any salt or derivative ofany of the previously listed compounds.
 6. The method of claim 1 whereinthe treatment mixture comprises: between about 0.1% and 95% by weightmetal complexing agent; between 1 and 10,000 parts per million (ppm) ofa corrosion inhibitor; between 1 and 10,000 ppm of a biocide; between 1and 10,000 ppm of a colloidal silica deposition inhibitor; between 1 and500 gallons per thousand gallons (gpt) of a mutual solvent; and between1 and 2000 parts per million of a surfactant.
 7. The method of claim 1wherein the treatment mixture further comprises between 0.1 and 95% ofacid(s) as pH modifier.
 8. The method of claim 1 wherein the injectingoperation further comprises: alternately injecting a first amount oftreatment mixture and a second amount of a diverting mixture into thewell.
 9. The method of claim 1 wherein the injecting operation furthercomprises: injecting the treatment mixture until the pressure within thewell reaches a predetermined target pressure calculated based on thefracture pressure of the nano-darcy shale formation; and upon reachingthe target pressure, shutting in the well.
 10. The method of claim 1wherein the injecting operation further comprises: injecting thetreatment mixture containing a metal complexing agent such as citricacid or EDTA in combination with hydraulic fracturing and injecting intothe formation in conjunction with propagation of the induced fractures.11. The method of claim 1 further comprising: monitoring at least one ofpH and well pressure during the maintaining operation; and initiatingthe removing operation based on results of the monitoring operation. 12.The method of claim 1 further wherein the metal complexing agent isselected from glutamic acid diacetic acid (GLDA), methylglycine diaceticacid (MGDA), β-alanine diacetic acid ((β-ADA), ethylenediaminedisuccinicacid, S,S-ethylenediaminedisuccinic acid (EDDS), iminodisuccinic acid(IDS), hydroxyiminodisuccinic acid (HIDS), polyamino disuccinic acids,N-bis [2-(1,2-dicarboxyethoxy)ethyl]glycine (BCA6), N-bis[2-(1,2-dicarboxyethoxy)ethyl]aspartic acid (BCA5), N-bis[2-(1,2-dicarboxyethoxy)ethyl]methylglycine (MCBA5),N-tris[(1,2-dicarboxyethoxy)ethyl]amine (TCA6), N-methyliminodiaceticacid (MIDA), iminodiacetic acid (IDA), N-(2-acetamido)iminodiacetic acid(ADA), hydroxymethyl-iminodiacetic acid, 2-(2-carboxyethylamino)succinic acid (CEAA), 2-(2-carboxymethylamino) succinic acid (CMAA),diethylenetriamine-N,N″-disuccinic acid,triethylenetetramine-N,N″′-disuccinic acid,1,6-hexamethylenediamine-N,N′-disuccinic acid,tetraethylenepentamine-N,N″″-disuccinic acid,2-hydroxypropylene-1,3-diamine-N,N′-disuccinic acid,1,2-propylenediamine-N,N′-disuccinic acid,1,3-propylenediamine-N,N′-disuccinic acid,cis-cyclohexanediamine-N,N′-disuccinic acid,trans-cyclohexanediamine-N,N′-disuccinic acid,ethylenebis(oxyethylenenitrilo)-N,N′-disuccinic acid, glucoheptanoicacid, cysteic acid-N,N-diacetic acid, cysteic acid-N-monoacetic acid,alanine-N-monoacetic acid, N-(3-hydroxysuccinyl) aspartic acid,N-[2-(3-hydroxysuccinyl)]-L-serine, aspartic acid-N,N-diacetic acid,aspartic acid-N-monoacetic acid, any salt thereof, any derivativethereof, or any combination thereof.
 13. The method of claim 1 furtherwherein the metal complexing agent is selected from acetic acid,acrylates, dihydroxymaleic acid, salts of dihydroxymaleic acid, EDTA(ethylenediamine tetraacetic acid), salts of EDTA, erythorbic acid,erythroboric acid, formic acid, gluconodeltalactone, GLDA (glutamic acidN,N-diacetic acid), salts of GLDA, HEDTA (hydroxyethylenediaminetriacetic acid), salts of HEDTA, HEIDA (disodium ethanoldiglycine),salts of HEIDA, MGDA (methylglycine N,N-diacetic acid), salts of MGDA,NTA (nitriolotriacetic acid), organic metal complexers, ligands,porphyrins, pigments, peptides, saccharides, nucleic acids, phosphonicacid, polyacrylic acid and citric acid in an amount sufficient tosequester at least a portion of a metal compound.
 14. A method forfracturing and stimulating a well in a nano-darcy shale formationcomprising: providing a treatment mixture containing between about 0.1%and 95% by weight metal complexing agent at a pH of between about 0 and10; injecting the treatment mixture into the well at a pressure greaterthan a fracture pressure of the nano-darcy shale formation until atleast some of the treatment mixture enters fractures in the nano-darcyshale formation, thereby allowing the metal complexing agent to bindwith at least some naturally-occurring metals contained within thenano-darcy shale formation; and removing spent treatment mixture andfracturing fluids from the well after the fractures are created, therebyremoving the bound naturally-occurring metals from the non-darcy shaleformation.
 15. The method of claim 14 wherein the injecting operation ispart of a fracturing operation that causes the fractures to occur in thenano-darcy shale formation.
 16. The method of claim 14 furthercomprising: fracturing the nano-darcy shale formation; and wherein theinjecting operation occurs after the fracturing operation causes thefractures to occur in the nano-darcy shale formation.
 17. The method ofclaim 16 wherein the injecting operation includes injecting proppantinto the fractures to occur in the nano-darcy shale formation.